On January 16, 2017, Indonesia took a large step toward
eradicating the cost recovery regime for upstream cooperation
contracts.

Regulation of the Minister of Energy and Mineral Resources
Number 8 of 2017 on Gross Split Production Sharing Contracts
("Regulation 8/2017") sets out a new economic structure
for production sharing contracts ("PSC") based on
dividing gross production between the state and PSC Contractors,
without a mechanism for the PSC Contractor to recover operating
costs.

The Minister of Energy and Mineral Resources ("MEMR")
is responsible for determining the final form and provisions of
PSCs incorporating this new gross split mechanism ("Gross
Split PSC"). We have not yet seen a model form Gross Split
PSC, but from the provisions of Regulation 8/2017 can draw the
following conclusions.

Cost Recovery to be Replaced by a Progressive Sliding Gross
Split Mechanism

Unlike existing PSCs, Gross Split PSCs will contain no mechanism
for PSC Contractors to recover sunk costs before production is
shared with the State. The required capital for operations is to be
fully funded, and the risk of operations is to be fully borne, by
the PSC Contractor.

Having said that, operating costs incurred by the PSC Contractor
can be taken into account as a deduction against the
Contractor's income tax liability. The often-disputed
classification of costs as permitted recoverable costs may
therefore still be relevant, but it is now in the context of
calculating income tax liability rather than allocation of shared
production volumes.

The traditional cost recovery mechanism will be replaced by a
gross split model that will apply a variable percentage production
share on a field-by-field basis, with the split adjusted by
reference to the characteristics of the specific field and the
revenue generated from the field's production, as follows:

The percentage gross split for a
field is determined by starting from a base allocation that is then
adjusted by "variable" components and
"progressive" components in accordance with the Annex to
Regulation 8/2017.

The base split for oil is 57
percent—43 percent for the state and the contractor
respectively. The base split for gas is 52 percent—48 percent
for the State and Contractor respectively.

The base split will then be adjusted
by "variable" components that address specific matters
affecting the cost of developing and commercializing the field.
These are: (i) the location of the field (onshore or offshore, and
if offshore, the water depth); (ii) the type (conventional or
unconventional) and depth of the reservoir; (iii) the availability
of supporting infrastructure; (iv) whether the field contains heavy
oil or the petroleum specification requires additional costs to be
incurred due to high levels of carbon dioxide or hydrogen sulphide;
(v) the availability of required equipment and goods in the
domestic economy; and (vi) whether the field is in the primary,
secondary, or tertiary phase of production.

A 5 percent uplift to the
Contractor's split will also be given for a plan of development
that is developed for the first time in a PSC work area—which
we interpret to mean the first plan of development under a PSC, at
which point the PSC moves from the exploration phase to the
production phase. No such 5 percent uplift is available for
subsequent plans of development in the PSC work area, or for
additional work under an existing plan of development. A 5 percent
reduction in the Contractor's share of petroleum may also be
applied in certain circumstances.

The "progressive"
components focus on the revenue generated from the field and adjust
the gross split from time to time by reference to the Indonesian
Crude Price ("ICP") and the cumulative total production
of oil and gas from the field.

The Contractor's production share
is lifted by increasing increments of 2.5 percent the further ICP
falls below US$70 per barrel (capped at a 7.5 percent increase
where ICP is below US$40), and is similarly reduced in increments
of 2.5 percent the further ICP is above US$85 per barrel (capped at
a -7.5 percent adjustment where ICP exceeds US$115). Some further
detail is required on how this will be calculated in practice; on a
straight reading of the Annex to Regulation 8/2017, as little as a
US$0.01 increase in the ICP, for example, could trigger a 2.5
percent reduction in the Contractor's percentage production
share, leaving the Contractor significantly worse off.

The PSC Contractor will also receive
an adjustment in its favor when a field is first producing, and as
cumulative production from the field increases, that favorable
adjustment reduces until it ceases once cumulative production
reaches 150 MMboe.

The percentage gross split to be
applied to a field will be determined at the time the plan of
development for that field is approved.

If a field does not achieve a
specified economic result, then an additional share of up to 5
percent may be allocated to the PSC Contractor. If a field exceeds
a specified economic result, the State may take an additional share
of up to 5 percent from the PSC Contractor.

After commercial production
commences, adjustments of the production share may be made if the
actual conditions experienced deviate from the variable and
progressive components used in setting the production share during
field development. Further, adjustments to the crude oil price
element of the progressive components will be made monthly based on
the results of evaluations carried out by the Special Task Force
for Upstream Oil and Gas Business Activities ("SKK
Migas"). Such evaluations will be based on the monthly
calculation of the ICP.

First Tranche Petroleum and Investment Credits

As a natural consequence of these adjustments, we expect that
the Gross Split PSC will also do away with: (i) the First Tranche
Petroleum structure, which was designed to ensure the State
receives a share of production without having to wait until all
approved costs were first recovered from production; and (ii)
investment credit allowances, as the variable components are
designed to incentivize PSC Contractors to invest in frontier,
deepwater, or other high-cost/high-risk areas by giving them a
greater share of production to compensate for the additional
investment risks and costs.

No Other Fundamental Changes

Regulation 8/2017 does not foreshadow any other fundamental
changes to the existing PSC regime. As with the existing PSC
structure:

Oil and gas remains the property of
the State until the delivery point of the production. Data obtained
from implementing Gross Split PSCs remains the property of the
State, and the existing strict confidentiality and disclosure
regulations will continue to apply.

SKK Migas retains overall control
(but limited to policy formulation toward work plans and budgets)
and management (through ensuring compliance with the approved work
plan) of operations, and PSC Contractors will still need to prepare
work programs and budgets for SKK Migas approval.

The 25 percent domestic market supply
obligations continue to apply, with payment for crude oil based on
the Indonesian Crude Price. Regulation 8/2017 is silent as to the
price to apply for natural gas, and we assume this will follow the
current practice.

Gross Split PSCs are likely to
contain standard PSC provisions such as those relating to mandatory
relinquishment of working area, minimum work and expenditure
commitments, restrictions on assignment, 10 percent Indonesian
participation rights (in this regard, no changes appear to be
proposed to the provisions set out in MEMR Regulation 37 of 2016),
prioritizing domestic labor and goods and services content,
conditions for contract extension, and creation of a reserve fund
for abandonment and rehabilitation activities.

All goods and equipment directly used
by PSC Contractors in upstream oil and gas activities become the
property of the State, to be developed by the Government and
administered by SKK Migas. This implies that, even in the absence
of a cost-recovery mechanism, the State is ultimately carrying the
costs of those goods and equipment, either by virtue of the
deductions to the PSC Contractor's tax liability or the
reimbursement is built in to the PSC Contractor's share of
production.

Certain bonuses will need to be paid
to the State. Regulation 8/2017 does not clarify what bonuses will
be payable under the Gross Split PSC. We expect a signature bonus
may still apply; however, we query whether payment of production
bonuses will be required as the progressive components already
build in a reduction to the PSC Contractor's gross split as
cumulative production levels reach certain milestones. It is
possible that production bonuses may be imposed at cumulative
production targets in excess of 150 MMboe.

Application

It appears that the new gross production split structure is
mandatory for all new PSCs granted on or after January 16, 2017,
including for PSCs that have expired and are being replaced.

For those existing PSCs that are expiring and being extended,
the original PSC cost recovery and profit split regime may continue
to apply, or the new gross split structure can be proposed for the
extension period. Those PSCs that were signed before the
Regulations came into force can also propose converting the
existing PSC to a Gross Split PSC at any time. Any proposed
conversion of an extension PSC or an existing PSC into a Gross
Split PSC would appear to be subject to gaining approval; however,
the Regulations are not entirely clear on the proposal and approval
process.

Where an existing PSC converts to a Gross Split PSC, all
operating costs incurred but not yet recovered under the previous
PSC terms can be added to the gross split in favor of the PSC
Contractor's share.

It is not entirely clear how this carrying-forward of
unrecovered costs will operate in conjunction with MEMR Regulation
30/2016 and MEMR Regulation 15/2015. MEMR Regulation 15/2015 sets
out, among other things, provisions for determining whether the
existing PSC Contractor, Pertamina, a different contractor, or a
combination of them would be appointed as the contractor for a work
area where an existing PSC is expiring and being renewed. MEMR
Regulation 30/2016 amended MEMR Regulation 15/2015 so that in the
event Pertamina or a third party is appointed as the new contractor
to take over the work area under the extended PSC, the new
contractor can enter into an agreement with the current PSC
Contractor for the funding of operations during the remaining term
of the existing PSC until the handover of operations. This was a
sensible clarification in order to ensure funds are properly spent
in maintaining the safe and effective operation of the work area by
an incumbent PSC Contractor who is fully aware that it would not be
party to the extended PSC and otherwise would have no means by
which to recover costs spent in the final months of operations, and
costs incurred pursuant to that funding agreement could be
recovered under the new PSC. However, if the extended PSC will take
the form of a Gross Split PSC, then the carrying-forward of
unrecovered costs is not an option, and we suggest it would be
prudent for these costs to be proposed as an adjustment to the
gross split percentages when applying for the extended PSC or when
the work area is retendered for award.

Partial Repeal of Unconventional Regulations

As a final note, MEMR Regulation 38/2015 on Expediting
Non-Conventional Oil and Gas Operations has been partially
repealed. MEMR Regulation 38/2015 made provision for three types of
PSCs for nonconventional oil and gas operations: (i) a traditional
form of PSC; (ii) a form of sliding scale gross production split of
a similar form to that introduced under Regulation 8/2017; and
(iii) a sliding scale PSC that incorporated a cost recovery
mechanism prior to the split of production and where the
Contractor's share of production reduced over time as
prescribed cumulative production levels were achieved. Under
Regulation 38/2015, the Directorate General of Oil and Gas would
determine which form of contract would apply.

Regulation 8/2017 repeals those provisions within Regulation
38/2015 that regulated sliding scale gross production split PSCs.
However, the remainder of Regulation 38/2015 has not been expressly
repealed. The effect of this is not entirely clear. It could be
interpreted as meaning that Gross Split PSCs are not available for
nonconventional operations, although this would be contrary to the
principle embodied in Regulation 8/2017 of moving away from cost
recovery mechanisms. Alternatively, it could be interpreted as
allowing the Directorate General of Oil and Gas to still determine
that any one of the three forms of PSC may apply to a new working
area contract for nonconventional resources, and that if a gross
production split model is selected, then the provisions of
Regulation 8/2017, rather than Regulation 38/2015, will apply to
that Gross Split PSC. This would remove certain provisions from
Regulation 38/2015 that would still be relevant for Gross Split
PSCs for unconventional resources, however, such as those setting
out how to determine the petroleum reserves to be used in setting
the plan of development and the sale of initial pre-plan of
development production to domestic markets (e.g. to facilitate a
multi-well pilot production test).

Developments in this area should be monitored.

The content of this article is intended to provide a general
guide to the subject matter. Specialist advice should be sought
about your specific circumstances.

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